The formation of hydrates in subsea oil and gas Wells is well understood and many methods have been attempted to alleviate the problems associated with these hydrates which have been described as like formation of ice crystals, which if severe enough can block the flow of hydrocarbons, shutting the production from a Well. The formation of hydrates are largely determined by the temperature and pressure of the hydrocarbons and occur when the temperature of the hydrocarbons from the subsea Well drops below a formation temperature, this formation temperature will also vary according to the chemical composition of the Well fluids. The Well fluids may also be affected by the formation of wax deposits which is also temperature dependent.
Production of hydrocarbons from offshore subsea oil and gas Wells is well established, and the prevention of the formation of hydrates and/or wax deposit is well known to be crucial to maintain the flow of hydrocarbons and the export to the market of the Well products. As subsea Wells become deeper and the distances from the Well to the processing facilities, either offshore or onshore, become longer the problem of hydrate formation and/or wax deposit is a limiting factor in the way in which an offshore oil or gas Field can be developed, and must be controlled. Typically, this is done by the injection of an inhibitor such as Monoethylene Glycol (MEG) or through insulation materials to coat the subsea Wellhead equipment and Pipelines and their connecting Jumpers (typically called Well Jumpers) and other Subsea Units or through electrical heating system on Pipelines. Subsea Units for the purposes of this discussion are any of the apparatus which is installed in a Subsea Production System (SPS) below the water line (i.e. subsea), which are used to transport hydrocarbons from the subsea Well(s) to an Export Pipeline. These mitigation measures are expensive solutions and lead to problems and costs with the injection and then extraction of the inhibitor from the hydrocarbons, or less than ideal coverage with insulation materials leading to ‘cold spots’. Even very small areas left uncovered can lead to a breakdown in the insulation barrier leading to a hydrate formation or major wax deposit which can result in a Plug. The distances between the Subsea Units or Onshore Unit and the Wells (step-out distance) can be the limiting factor in whether a subsea oil or gas Field, or a portion of it, can be developed.
Other novel approaches have been patented in the attempt to control Hydrates and/or Wax deposits. Export Pipelines can be of a Pipe-in-Pipe design, or installed with various insulation materials or Heating System such as Trace Heating or Direct Electrical Heating.
Well jumpers present a particular set of problems because they connect the high pressure Wells to a subsea Manifold (or other processing equipment or Subsea Unit), and the Export Pipeline without the escape of hydrocarbons. A blockage caused by hydrates can lead to loss of production and lost revenue, and a fracture (or other loss of integrity) in the Well Jumper could result in serious pollution problems. Well Jumpers may be installed in trenches or covered by rock-dumping if water depth is shallow enough to be a danger to fishing activity. Well Jumpers may be Rigid or Flexible. Rigid Well Jumpers are difficult to fabricate and install subsea as they usually require to be fabricated when the subsea Tree (also known as a Subsea Christmas Tree or XT) and the subsea Manifold (or other processing equipment or Subsea Unit) are fully installed and subsea metrology is performed between two flanges (or other connection method) to determine the exact size of the Rigid Well Jumper. Fabrication of a Rigid Well Jumper with an insulation layer which has no ‘cold spots’ is obviously difficult to achieve. These Well Jumpers also limit the location of each Well relative to each other (the Field layout) as there are limits to the size of Well Jumpers for practical reasons such as installation vessel size and handling/deployment difficulties.
Template/Manifold solutions exist where the subsea Wells are drilled from a very heavy steel structure requiring that the Wells are drilled from that location and usually after the steel structure is lowered to the seabed by a heavy lift vessel, reducing but not eliminating the number of Well Jumpers, but placing restrictions on the sequence and timing of drilling activities and Subsea Unit installation. However, the Pipeline from such structures to Production Unit are affected by the same risks of hydrate formation or wax deposit.
Major accidents in oil and gas offshore industry have highlighted that these subsea Wells can be difficult to control in the event of a ‘blow-out’ (uncontrolled release of hydrocarbons), and the last and most difficult way to intervene and control the Well is to drill a ‘Relief Well’. This is when a second Well is drilled and intersects with the first ‘rogue’ Well, and requires great accuracy and can take many months. A Relief Well can be drilled at the same time as the primary Well, or soon after, but the use of subterranean Channels in a ‘Production Field’ will greatly reduce the additional cost of such a Relief Well.
It is an object of at least one aspect of the present invention to obviate or mitigate at least one or more of the aforementioned problems.
It is a further object of at least one aspect of the present invention to provide an improved method for prevention of hydrates in an oil and gas Well by utilizing the latent heat in the sub-soil and providing subterranean Channels to facilitate the provision of Relief Well access.